In rotary drilling operations a drill bit connected to a drill string is used to establish a borehole in the earth. The drill string is supported and powered by a drilling rig located at the earth's surface, or, in the case of offshore drilling, on a drillship or marine platform. The drill string is composed of sections of pipe which are joined at threaded connections. Immediately above the drill bit the drill string includes several drill collars, which are heavy-walled tubular elements adding weight to the drill bit to improve its performance. The remainder of the drill string, extending upward from the drill collars to the surface, is composed of drill pipe.
From time to time in the course of drilling operations, drilling is stopped and the drill string is pulled away from the bottom of the borehole. Most frequently, this is done for the purpose of adding an additional length of drill pipe. This involves lifting the drill string a short distance to bring the uppermost point in the drill string, the connection between the kelly and the drill string, to a location just above the rig floor. This lifting of the drill string also occurs during temporary cessations in drilling operations, when the drill string is repeatedly lifted and lowered a short distance within the borehole to prevent differential sticking of the drill string against the wall of the borehole. Periodically during drilling operations, the drill string is entirely withdrawn from the borehole, most commonly for the purpose of changing the bit. Withdrawing the entire drill string from the well is termed "tripping out", reinserting the drill string is termed "tripping in".
As the drill string is rotated by the drilling rig to cause the drill bit to cut into the rock, drilling fluid, commonly referred to as mud, is pumped to the drill bit through the tubular drill string. The drilling fluid passes into the borehole through nozzles in the drill bit and then flows back to the surface through that portion of the borehole outside the drill string, termed the annulus. The drilling fluid is quite important in the drilling operation, serving to cool and lubricate the drill bit, to carry cuttings away from the bottom of the borehole, to support the walls of the borehole and to minimize the pressure differential between the borehole and the surrounding formations.
As the drill bit penetrates a subterranean formation, that formation is brought into fluid communication with the surface via the borehole. If the pressure of the formation exceeds that of the borehole, the fluids in the formation (most typically water, oil or gas) can be forced into the borehole under pressure and released to the surface in an uncontrolled manner. This condition is commonly termed a blowout. To prevent this, the density of the drilling fluid is carefully controlled to maintain the pressure in the borehole at a level such that the fluids in permeable formations are not forced into the borehole.
Well control problems can also arise if the pressure in the borehole significantly exceeds that of any formations traversed by the borehole. Should the density of the drilling fluid be greater than that of a permeable formation, it is possible for drilling fluid to be forced into the formation. This condition is termed lost returns. In some instances the hydrostatic pressure of the drilling fluid can be great enough to fracture a weak formation, causing drilling fluid to be lost into the formation at a rapid rate. Should there also be a relatively high pressure formation at some other point along the borehole, this loss of drilling fluid to the weak formation can cause a drop in hydrostatic pressure head in the borehole of sufficient magnitude to induce a blowout from the high pressure formation. To minimize the potential for lost returns, it is usually desired to control the density of the drilling fluid such that the pressure in the borehole does not greatly exceed that of the permeable weak formations.
The most effective manner of guarding against blowouts is to monitor the well to determine the onset of formation fluid intrusion. If this initial intrusion, commonly referred to as a kick, is detected at its inception it is usually not difficult to prevent the situation from advancing to a blowout. Similarly, lost circulation is most easily corrected when the loss of drilling fluid is detected at an early stage.
A well known technique for detecting kicks and lost circulation in the course of drilling is delta flow monitoring. This method involves comparing the flow rate of drilling fluid injected into the well at the surface to the rate at which drilling fluid exits the well at the surface. After averaging these rates over a suitable time period, it becomes possible to determine the differential flow rate commonly referred to as the "delta flow rate". This represents the cumulative change in the amount of the drilling fluid within the well. A net addition of drilling fluid to the borehole is indicative of lost returns. Likewise, an excess of returned drilling fluid over injected drilling fluid signals a potential blowout. Upon receipt of an indication of such well control problems, remedial measures may be initiated. These remedial measures are usually designed to lessen the pressure differential between the borehole and the surrounding formations, or to seal the permeable formations through which fluid migration is occurring.
Well control problems occur with relatively great frequency in the course of tripping, adding a stand of drill pipe to the drill string, reciprocation, and other operations in which the drill bit is moved to and from the bottom of the borehole. Such problems are thought to result from borehole pressure transients induced by the swabbing and plunging action established by relatively rapid withdrawal and insertion of the drill string in the borehole. Well control problems in the course of such drill string movement have typically been monitored with various modified delta flow comparison techniques.
The most basic prior art techniques of delta flow monitoring assume that the volume of that portion of the borehole and associated drilling equipment which can be occupied by drilling fluid is constant. This assumption is generally satisfactory where the rate of drill string movement into or out of the borehole is negligible, as is generally the case in normal drilling ahead. However, to establish adequate accuracy in delta flow monitoring techniques utilized in the course of tripping and other phases of the drilling operation in which the rate of movement of the drill string is significant, it is necessary to account for these changes in volume.
Prior art techniques of accomplishing such compensation are largely directed to tripping, ignoring other situations in which the drill string is lifted and lowered within the borehole. Such prior art techniques generally provide some manual means of correcting for the changing volume of drill string within the borehole. In one commonly utilized technique, drilling fluid is circulated from a trip tank into the borehole and drilling fluid exiting the borehole is returned to the trip tank. The fluid level within this trip tank is manually checked every seven to ten stands of drill pipe. The level of drilling fluid within the trip tank should increase approximately one barrel per stand tripping in. While tripping out the level should decrease by a like amount. A difference between the anticipated and actual changes in the drilling fluid level represents of a net transfer of fluid between the formation and the borehole.
A related technique for monitoring delta flow in the course of tripping is disclosed in U.S. Pat. No. 3,729,986, issued May 1, 1973. The volume of each segment of the drill string is known, After a given number of segments have been tripped in or out, the total equivalent volume of these stands is compared to the volume of drilling fluid that must be added or removed to bring the drilling fluid back to the reference level in the bell nipple which it occupied prior to tripping the stands. Any difference between the volume of the stands and the change in volume of the fluid represents a net transfer of fluid between the formation and the borehole. Such systems are disadvantageous in that there is often a significant delay between the onset of a well control problem and the detection of that problem.